Field of the Invention
1. The present invention relates to the operation of steam turbines and electric power plants and more particularly to the implementation of a plant unit master in the operation of steam turbines and electric power plants.
Description of the Prior Art
2. In the prior art, boiler and turbine controls have been engineered and installed as separate systems. Typically, the turbine control loop was designed independent of the boiler control loop and operated to control steam as required by the turbine. More specifically, the turbine control loop operated as a boiler follow system in which a load demand signal, as provided by the operator or an automatic dispatcher system (ADS), controlled the position of the turbine governor valves. The change in system steam pressure is measured to, in turn, control the input of fuel, air and water to bring the system steam pressure to a predetermined level. Since throttle or system steam pressure is a function of the boiler fuel input, the boiler and turbine tended to follow the fuel input rather than the governor valve position. Such a boiler follow system when applied to a supercritical once-through boiler, did not keep the boiler pressure above critical at all times.
Alternatively, there was suggested a turbine follow system in which the operator or ADS set a new load demand whereby the fuel, air and water inputs were respectively controlled. As the steam pressure varied, the position of the governor valve was adjusted to set the system steam pressure at a predetermined level. Though such turbine follow systems did maintain pressure at all times, their overall system response was considered poor. By attempting to maintain a constant pressure, the turbine follow system did not make maximum use of the stored energy in the boiler. Further, as larger units and greater numbers of such units were placed into service to meet ever-increasing power energy requirements, the control of power generation of each unit required improvement in order to achieve good frequency control over the entire system. In addition to systems requirements, there was a strong requirement that new methods be developed to extract energy from the boiler as well as to set limits by which the boiler could be operated safely and efficiently. As discussed in the article, "System Design Considerations for Advanced Utility Unit Control," by T. A. Rumsey and D. L. Armstrong, presented at the 14 th Annual Southeastern ISA Conference, Apr. of 1968, the required improved control of power generation is efficiently accomplished by achieving a close coordination of the boiler and turbine controls. As suggested in this article, the controls for the boiler and turbine are placed in parallel in a manner similar to the boiler follow system, except that the steam pressure is varied to take advantage of the energy stored in the boiler. The turbine regulates steam pressure, but with a changing set point derived from the error between load demand and actual unit power output. If the load demand is higher than the actual unit power output, the signal applied to the pressure controller calls for a lower steam pressure, thus opening the governor valve and temporarily increasing megawatts as the pressure drops. The same signal applied to the pressure controller effecting a lower pressure in response to detection of a megawatts output below the required demand level, increases the boiler inputs (water, air and fuel). This control action continues until the megawatt error is zero, at which time the steam pressure is at its normal value. Such integrated control techniques have been applied to once-through, supercritical boilers and to drum-type subcritical boilers.
A significant aspect of the integrated control of turbines and boilers is the use of feed forward control techniques to minimize interaction and to extract the best possible dynamic response. Generally, such feed forward control is effected by applying load demand signals from either the ADS, a computer, or a manual operator control, simultaneously to the boiler and turbine. The advantages of such a control means that subloop process changes are made simultaneously with load changes before subloop errors exist. Feedback controllers are used as a final trim on the process subloop to correct for minor non-linearities and static effects. As a result, it is possible to extract more efficiently energy from the boiler of an individual unit, whereas on a system level, each of a plurality of units may be operated so as to maintain system frequency integrity.
From the general concept of applying load demand signals from a common source (termed herein, the plant unit master) simultaneously to the turbine and boiler, there has developed more sophisticated control systems employing this basic technique, whereby the boiler-turbine control functions are closely coordinated. For example, such a coordinated control may include adjustments for the high limit, low limit and rate of change of limits for various turbine-boiler control parameters such as load, system steam pressure, and fuel inputs. Further, there is provision for run-back and run-up in response to some abnormal condition in the plant auxiliaries, so that the unit will be operated safely and within the capability of the auxiliaries in service. As will be elaborated upon below, coordinated control also provides for transferring to any of a number of desired modes of operation.
As explained above, the basic concept of integrated control is to apply simultaneously load demand signals to the boiler control system and to the turbine control system in a feed forward manner whereby minor or trim corrections are made in response to detection of throttle pressure error, megawatt error, and frequency bias. In particular, the measured throttle pressure is compared to a reference level determined by a set point to provide the throttle pressure error, which subsequently is inntegrated and applied to the turbine control. The throttle pressure error signal serves to adjust the load set point. The output of the turbine is measured and compared with a reference to provide megawatt error, which is integrated and also is used in combination with the throttle pressure error signal to set the air and fuel inputs to the boiler.
During steady state operation, the megawatt generation is proportional to the fuel input. More specifically, the integrated generation error adjusts the throttle pressure set point to permit more effective transfer of the stored energy in the boiler to the turbine. This transfer of stored eneregy may be seen more readily from a specific example of operation. Where an increasing load demand is applied, the throttle pressure and the megawatt generation will be low. Under these conditions, the throttle pressure set point is increased by an amount proportional to generation error, whereby the energy stored in the boiler will be transferred to the turbine to increase its power generation. At the same time, the boiler inputs of air, fuel and water are increased momentarily to likewise increase the throttle pressure, which is lowered momentarily as the governor valves are opened to permit greater steam flow.
In effecting turbine control, the ratio of impulse chamber pressure to throttle pressure is used in that it is a more accurate indication of valve area, which is linear with load when operating at rated pressure. The turbine load demand is summed with the integrated throttle pressure error signal and a signal indicative of the ratio of the impulse chamber pressure to throttle pressure. The error signal then is used to adjust the position of the control valves directing steam into the turbine.
A frequency bias is provided as a function of speed error derived between a reference speed level signal and the measured rotational speed of the turbine. The frequency bias is applied to the turbine and boiler control systems to permit the entire unit to share properly in frequency control by increasing or decreasing the boiler and turbine load demand signals as required. In particular, the frequency bias is applied to adjust the megawatt error signal, which in turn controls the boiler inputs. In the turbine control, the frequency bias similarly adjusts the valve position error signal.
Thus, it can be seen that by coordinated control of the turbine and boiler, no significant time delays are introduced between the increase of boiler inputs and a corresponding change of pressure. In non-integrated systems of control, first the turbine would be adjusted and then the boiler. By contrast, the integrated mode of operation permits both the turbine and boiler to be controlled at once, whereby greater overall system frequency control is achieved, and a more efficient transfer of the energy from the boiler to the turbine is provided.
In addition to the steady state mode of operation (local and remote coordinated), the following modes of operation are available to start up the unit as well as to provide for certain abnormal contingencies:
(1) Plant Start
(2) Go
(3) Ramp
(4) Coordinated Turbine Follow
(5) Coordinated Boiler Follow
(6) Boiler Manual
(7) Remote Coordinated
(8) Local Coordinated
The Plant Start Mode is an automatic mode, not selected by the operator, and is an initial mode of operation in which the turbine and boiler are prepared individually to operate together for generating power. The boiler is lighted off and fired under the control of the operator, while the inputs are controlled selectively. Further, it is necessary to supply input to the boiler to provide a predetermined pressure and to preheat the turbine under controlled conditions as by slowly rotating the turbine and by supplying steam from an auxiliary source, to prepare the turbine to receive the boiler steam. More specifically, the turbine is unlatched and rotated by a turning gear while steam is supplied under controlled conditions through gland seals, an appropriate pull vacuum is established, and the drain valves are opened to a predetermined condition, whereby the temperature of the turbine is gradually brought up to a predetermined level. Further, the desired terminal speed and acceleration are set by the operator.
Having established the proper boiler steam and turbine conditions, the operator initiates a Go Mode, wherein the unit master directs a speed error signal only to the turbine. The signal applied to the boiler controls is held constant at a predetermined value corresponding to load. The turbine accelerates to the preset terminal speed at a preset acceleration by wide-range speed control operation of the turbine throttle valve. When the turbine has arrived at th preset speed, transfer will be made from full-arc to partial-arc control of the valves. During further operation, the throttle valves are set wide open, while the turbine governor valves are set to control steam flow to the turbine. At this point, the turbine has been brought to near-rated speed and after suitable operator checks, the main circuit breaker may be closed and the governor valves are disposed quickly to a position that will result in a predetermined percentage of load at the existing steam condition.
The Ramp Mode is the first truly coordinated mode in which the boiler and turbine are operated together to control the gradual build-up of the system steam pressure and to control the heating rate of the turbine to avoid placing undue stress on the turbine parts. In a first step, throttle pressure is increased to its rated value while the turbine governor valves are held at an essentially constant position. During this initial stage, a transfer signal is generated to be combined with a load reference signal derived from the plant unit master, whereby the governor valves are maintained in a nearly fixed position. In another method of controlling the boiler, the steam pressure as controlled by the throttle valves and the boiler firing are increased along a ramp to a predetermined load level. The second, ramping phase is performed automatically by setting the ramp rate and the ramp end point in load. In particular, a reference ramp signal is generated according to the ramp rate and the ramp end point to define the pressure set point, which is compared with the measured throttle pressure to provide a pressure error signal; the pressure error signal is integrated and applied as an input to the automatic governor valve controls. At this time, the boiler master is in an Automatic Mode, whereby the plant unit master output becomes the boiler demand signal. Thus, as the demand signal increases along a ramp, the boiler firing increases thereby to increase the throttle pressure along a similar ramp. In the Ramp Mode, the megawatt error signal is not used to provide boiler control.
At the termination of the Ramp Mode, the plant unit master automatically reverts to a "hold" condition in preparation for being operated in the Remote or Local Coordinated Mode, as generally explained above. The operator effects the transitions by setting the desired load share with respect to the remaining units of the system and then initiates the transfer to either the Local Coordinated Control Mode, wherein the operator has direct control over the unit load demand, or to the Remote Coordinated Control Mode, wherein the unit load demand is controlled either by an automatic dispatching system (ADS) or a computer.
The Boiler Manual Mode permits the operator to control the boiler independently of the plant unit master, which continues to provide demand signals to the turbine. This mode is particularly useful in the initial firing of the boiler.
In the event of certain abnormal conditions, the plant unit master automatically transfers to either a Coordinated Boiler Follow Mode or to a Coordinated Turbine Follow Mode. More specifically, if an unusual turbine condition develops, the plant unit master automatically transfers to the Boiler Follow Mode wherein the operator determines the load demand at a predetermined, constant governor value setting and as a result, the governor values are set to a predetermined position. Thus, the inputs to the boiler are controlled to derive, in turn, a desired throttle pressure. If unusual boiler conditions develop, the Coordinated Turbine Follow Mode is automatically set, wherein the boiler is set to operate according to predetermined limits and the governor valves are adjusted to maintain substantially constant pressure.
The plant unit master includes a digital reference for the electrohydraulic governing system, which sets the operational capability for the plant unit master in terms of the set points and limits for turbine and boiler operation. Such a digital reference is further described in a paper entitled, "Electrohydraulic Control for Improved Availability and Operation of Large Steam Turbines", and presented by M. Birnbaum and E. G. Noyes to the ASME-IEEE National Power Conference, September 1965. It also has the ability to receive digital or analog signals for back-up purposes. Further, the digital reference system generates the load demand for on-line and off-line modes of plant operation, whereby the number of operating stations is minimized. In particular, limit, run-back and run-up signals are applied to the digital reference system. The limit signals confine the load demand signal derived from the plant unit master to protect the system when abnormal conditions develop in the auxiliaries. For example, if one of the water or oil pumps becomes inoperative for any reason, a predetermined limit is disposed upon the load demand signal. Run-back signals reduce the unit demand signal from the digital reference to a safe value corresponding to the availability of fuel, water, air and generator coolant. Run-up signals are used to increase the unit demand signal from the digital reference to correspond to the minimum level of energy generation by the boiler. For example, the boiler burners may require a certain minimum fuel requirement to provide a minimum power output, which must be absorbed by the remaining part of the generating unit.
The basic plant unit master or coordinated techniques as described above, have been adapted to the use of electric power plants operated by steam turbines for which the steam supply is provided by a nuclear boiling water reactor, as described in U.S. Pat. No. 3,630,839 of Podolsky. The modifications to the coordinated control from that described above primarily relate to the boiling water nuclear reactor, the power operating level of which is determined in part by the accumulation of steam voids on the heat transfer surfaces thereof. In a boiling water nuclear reactor, the nuclear fuel is structured with a suitable geometry to provide for a sustained chain nuclear reaction as the coolant water passes through the fuel arrangement. The nuclear fuel is contained within a plurality of elongated metallic tubes, which form the reactor core. The coolant flow is directed about the metallic tubes of the reactor core; as a result, the design of the core with respect to eliminating void accumulation on the surface of the tubes is significant. In this regard, it is desirable to operate the turbine inlet valves to determine the turbine and generator load level subject to the pressure regulating demands of the reactor. Further, the steam turbine energization level is determined by the flow of the turbine inlet steam which, in turn, is determined by the steam conditions at the outlet of the steam source and by the steam inlet valve positioning.
In such nuclear boiling water reactors, a steam bypass system is provided to direct the steam flow from the reactor output to the plant condenser. In the Start-Up and Shut-Down Modes of operation, it is necessary to control the amount of steam pressure supplied to the turbine; the steam bypass system redirects the excess steam not required by the turbine to the condenser.
The coordinated control as described in the noted patent provides back-up speed control uniformly without dependence on turbine operating level, by applying a load demand signal as derived from a digital reference system to the reactor control system and to the electrohydraulic inlet valve control system. Further, a speed error signal signifying the difference between a speed reference signal and the measured speed of the turbine, is applied also to the reactor control system and to the electrohydraulic inlet valve control system, to efficiently control turbine acceleration during Start-Up, frequency participation during the Load Mode of operation and turbine deceleration during Shut-Down. The measured values of throttle pressure, megawatts and the ratio of impulse pressure to throttle pressure are used in a manner very similar to that described above. With particular regard to the water reactor-steam turbine operation, improved performance results from the operation of the pressure control system to control a bypass valve function generator to generate a signal to control the bypass valve system, whereby the excess steam not needed by the turbine during load control is diverted directly to the condenser. The bypass valve energizing signal is limited by the detected impulse pressure.
In such coordinated control systems, the various functions described were implemented in a manner in which the coordinated control could be considered distinct from that of the boiler control and the turbine control. As explained above, the digital refernce receives for the purpose of coordinated control, the run-up, run-back and limit signals to ensure the safe operation of the turbine, boiler and auxiliaries. In view of the increasing power demands placed upon large generating systems, it becomes increasingly important to avoid unit failure. Though the availability of large once-through supercritical units does provide for relatively increased power generation, their increased size has resulted in an increase in their failure and lack of availability to the power system. Their relatively poor record of availability is due in part to their complexibility, requiring increased control hardware. Thus, it is highly desirable to integrate the control system even further, whereby the various safety limits, and other control and limit signals are available to each of the control functions of the coordinated system. In this regard, the present analog coordinated systems require additional hardware to adjust or scale the various values before being applied from one control section to the next. In such analog systems, the limits as stored in the plant unit master are available to one of, but not both, the turbine and boiler control systems, at a single instant in time. Further, improved coordinated control is needed to ensure faster response of the entire turbine-boiler system whereby efficient, rapid load and speed control may be assured.